This section provides background information to facilitate a better understanding of the various aspects of the present invention. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.
Significant oil and gas reserves have been discovered, and continue to be discovered, beneath various bodies of water throughout the world. In the past, technology limited offshore drilling and production to relatively shallow locations in shoreline areas where the depth of the water ranged from a few feet to several hundred feet. Presently the industry has conducted drilling operations in water depths that exceed more than 10,000 feet, and it is anticipated that these operations may continue to move to even deeper waters.
Whenever drilling operations are conducted in deep water, greater costs and logistical challenges are encountered as compared to operations in shallower depths of water. One major cost of drilling and producing a well is simply the cost of leasing the platform and other equipment. Each day of rig time can cost hundreds of thousands of dollars. As such, drilling operations should be planned and designed to run as efficiently as possible. These increased costs are compounded by the additional time needed to deal with the challenges of operating in deep water environments, and the make-up and break-out of tubulars during a conventional drilling operation, for example.
Offshore drilling operations comprise three general phases. The initial phase (e.g., top hole drilling phase) comprises constructing the wellbore in the shallow formations below the seabed prior to installing a blowout preventer (“BOP”). In the top hole drilling phase, an upper portion of the wellbore is formed, for example by jetting and/or drilling a hole, and then a section of casing, referred to generally as a conductor, is positioned and cemented or jetted in the hole. The initial section of the wellbore may comprise one or more sections of casing which typically decrease in diameter (e.g., a tapered string) as the depth increases from the surface of the earthen formations (e.g., the seabed). For example, the top hole section may comprise a first (e.g., top) section having a casing diameter of about 30 inches (66 cm) extending from the seabed to about 300 to 400 feet, and a second section having a casing diameter of about 20 inches (44 cm) extending down from the seabed to about 4,000 feet.
The second phase, referred to herein as the primary drilling phase or the bottomhole drilling phase, is performed after the BOP is installed. Once the top hole section is completed with a conductor and a wellhead, the BOP is conveyed from the drilling platform down through the water column on a riser (e.g., marine riser) and is landed on the wellhead. Risers comprise a large diameter tubular string, for example, having a 21 inch (46.2 cm) outside diameter (“OD”), that provides a conduit from the wellbore, via the BOP, to the surface of the water column located proximate to the drilling platform. Traditionally, the bottomhole drilling phase is performed through the riser. For example, after the BOP is installed, the drillstring is made-up at the drilling platform and run into the wellbore through the riser. Actuation of the drill bit, which is a component of the bottomhole assembly (“BHA”), is conventionally performed through the riser, and the riser is also used to circulate the drilling fluid (e.g., drilling mud). When a section of the wellbore is drilled (or a tool failure occurs), the drilling string is pulled out of the wellbore via the riser to the drilling platform. Additionally, operations including without limitation, drilling, running casing, cementing casing, well testing, well logging, well stimulations, formation fracturing, and the like which are all traditionally performed through the riser.
Once the wellbore is drilled and the downhole portion is completed to the desired depth, post drilling operations can be performed. The BOP is then removed and retrieved to the surface, and for a successful well, a downhole production assembly and a tubing string are installed down hole, and a valve tree (e.g., such as a Christmas tree that is comprised of control valves, gauges, and chokes) is installed at the wellhead.
Traditionally, offshore wellbores are formed (e.g., drilled, completed) using a single load path (e.g., derrick, rig, drilling assembly), thus requiring all wellbore tasks (e.g., drilling, completion, stimulations, workovers, etc.) to be performed from a single assembly. Recently, efforts have been made to decrease the time required to drill wells offshore by performing some tasks simultaneously. For example, U.S. Pat. Nos. 6,085,851 and 6,056,071, each to Scott et al., disclose a multi-activity apparatus and method for conducting drilling operations. In general, Scott et al. disclose a drilling platform having dual drilling assemblies (e.g., separate load paths and/or derricks). In the method disclosed in Scott et al., some activities during the top hole drilling phase and the post drilling phase are performed substantially simultaneously by a main derrick and an auxiliary derrick. However, according to Scott et al., drilling operations are performed from a single load path during the bottomhole drilling phase (i.e., after the BOP has been installed).
A multi-activity drilling facility is also disclosed in U.S. Pat. No. 6,766,860 to Archibald et al. The '860 patent discloses an assembly and method for suspending tubular strings prior to being run into the wellbore (e.g., staging operations) and/or for suspending tubulars that have been removed from the riser and the wellbore. In one example of a post drilling operation, the BOP is removed from the wellbore and moved laterally away from the wellbore and is then suspended from the drilling platform, while the valve tree (e.g., Christmas tree) is run down to the seabed and installed at the wellbore. Consistent with other prior art systems, the wellbore tasks (e.g., drilling, casing, logging, testing, cementing, stimulations, workovers, etc.) are performed from a single load path.
Another solution proposed to improve the efficiency of offshore drilling operations is disclosed in U.S. Pat. No. 6,443,240 to Scott. In the '240 patent, two risers extend from the drilling platform and are both connected to the wellbore though the BOP. Tasks and operations such those associated with drilling and completion, for example, and without limitation to, jetting, driving pipe, drilling with pipe (e.g., drillpipe, casing, liners), cementing, setting casing, hanging liners, gravel packing, logging, fluid sampling, formation testing, measuring with sensors, production and/or injection testing, formation stimulation, and fracturing can be conducted through the first riser, while another drilling operation is staged in the second riser. For example, when the first drilling assembly utilized in the first drilling task is withdrawn from the wellbore into the first riser, the second drilling assembly, staged in the second riser, can be run into the wellbore through the second riser. The proposed improvement in efficiency requires installation and maintenance of two riser assemblies.
There is, therefore, a desire to reduce the time required to drill and complete a wellbore. There is a further desire to provide a deep water drilling method and apparatus that can more fully utilize a platform rig assembly with multi-activity exploration and/or production capabilities, as well as completion, testing, workover, and maintenance capabilities. There is a still further desire to provide an apparatus and method for eliminating the use of some physical equipment traditionally required to conduct offshore drilling operations. And, there is yet a still further desire to provide a drilling system that is more efficient thus decreasing the costs associated with leasing capital drilling equipment.